Norwegian Petroleum Directorate Research Articles (Page 1)

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217671, “Enhancing Information Retrieval in the Drilling Domain: Zero-Shot Learning With Large Language Models for Question Answering,” by Felix J. Pacis, SPE, University of Stavanger, and Sergey Alyaev and Gilles Pelfrene, SPE, NORCE, et al. The paper has not been peer reviewed. _ Finding information across multiple databases, formats, and documents remains a manual job in the drilling industry. Large language models (LLMs) have proven effective in data-aggregation tasks, including answering questions. However, using LLMs for domain-specific factual responses poses a nontrivial challenge. The expert-labor cost for training domain-specific LLMs prohibits niche industries from developing custom question-answering bots. The complete paper tests several commercial LLMs for information-retrieval tasks for drilling data using zero-shot in-context learning. In addition, the model’s calibration is tested with a few-shot multiple-choice drilling questionnaire. Introduction While LLMs have proven effective in various tasks ranging from sentiment analysis to text completion, using LLMs for question-answering tasks presents a challenge in providing factual responses. Pretrained LLMs only serve as a parameterized implicit knowledge base and cannot access recent data; thus, information is bounded by the time of training. Retrieval augmented generation (RAG) can address some of these issues by extending the utility of LLMs to specific data sources. Fig. 1 shows a simplified RAG-based LLM question/answer application. RAG involves two primary components: document retrieval (green boxes), which retrieves the most relevant context based on the query, and LLM response generation (blue boxes). During the response generation, LLM operates based on the prompt, query, and retrieved context without any change in the model parameters, a process the authors term as “in-context learning.” Methodology Two experiments have been conducted: The first one is a few-shot multiple-choice experiment evaluated using the SLB drilling glossary; the second is a zero-shot in-context experiment evaluated on drilling reports and company reports. Multiple-Choice Experiment. SLB Drilling Glossary. For the multiple-choice experiment, a publicly available drilling glossary served as a basis for evaluation. A total of 409 term/definition pairs were considered. Five term/definition pairs were chosen, serving as few-shot default values, while the remaining 404 pairs served as the multiple-choice questions. Four choices were given for each term/definition question pair, where one was the correct answer. The three incorrect choices were picked randomly from all possible terms minus the true answer. Zero-Shot In-Context Experiment. Norwegian Petroleum Directorate (NPD) Database. The authors explored the wellbore history of all individual exploration wells drilled in the Norwegian shelf in the NPD database. In this experiment, 12 exploration wells were randomly chosen for evaluation. In addition to these drilling reports, information about the stratigraphy of three additional wells was added. Annual Reports. Annual reports of two major operators in Norway for 2020 and 2021 also were considered. These consisted of short summaries that presented the main operational and economic results achieved by the company throughout the year. These reports were added to the evaluation to balance the higher technical content of the wellbore-history reports.

Almost every day, petroleum engineers are coming to realize that they’ve got an arsenal of good ideas on how to leverage large, messy data sets to add value to their businesses. Those who have enlisted in the Analytics Army have progressed from siloed digitalization attempts to well-concerted digital transformation strategies that reflect high levels of organizational digital maturity. Paper SPE 220686 hits an undeniable sweet spot for production and reservoir engineers, using an array of machine-learning methods to accurately predict real-time well status. Practicality here is evident, because only widely available surface-measured pressures, temperatures, and choke-valve positions are used to classify online and offline well status. The 99% accuracy levels achieved represent a boon not only for those interested in more-reliable rate allocation but also for well-integrity and flow-assurance applications. With ever-increasing data acquisition volumes, data-labeling and categorization problems increase in lockstep. After all, how well can your luggage be found without proper tagging? Anyone remember the 2022 summer of lost luggage? The value proposition of paper SPE 218865 is clear, using a combination of natural language processing for coiled tubing operations reports and pattern recognition of multimodal job data to automatically label the job types and technologies used. A myriad of other cases spring to mind for repurposing the solution to transform current onerous processes of metadata generation. In the aftermath of the explosion in popularity of all things generative artificial intelligence, paper SPE 217671 steals the limelight. This paper exploits good data foundations by painting a roadmap to building your own drilling chatbot adviser. Compared with other generalized large language models, the zero-shot learning technique allows the chatbot to answer queries for drilling domain-specific knowledge that it hasn’t explicitly “seen.” The authors have even publicized the training data sets collated from the Norwegian Petroleum Directorate to enable quick and relatively inexpensive replication. Recommended additional reading at OnePetro: www.onepetro.org. URTeC 4045912 Using Machine Learning To Automate Fracture-Driven-Interaction Analysis by Reid Thompson, Momentum AI, et al. SPE 220833 Preliminary Research on Applications of Large Language Models in the Exploration and Production Industry by X.G. Zhou, PetroChina, et al. SPE 220714 Automated Well and Reservoir Management Using Hybrid Physics and Data-Driven Models—Case Study by Azreen Mustafa, Hess Corporation, et al.

Summary Over the past years, it has become clear that greenfield oil production forecasts are subject to strong optimism and overprecision biases: Significant early production shortfalls are the rule rather than the exception and the elicited uncertainty range is generally too narrow. This has large negative consequences for the net present valuation of such investments. A study from 2011 based on post-factum evaluation of greenfield production forecasts suggests that there is a causal relationship between certain project/field characteristics and production attainment (i.e., optimism bias). However, while self-reported causes of failure may provide interesting insights, such analyses are subject to cognitive hindsight bias. It is therefore necessary to test such claims more rigorously. Research on megaprojects in other industries suggests that forecasting bias is omnipresent but is stronger in certain circumstances (e.g., information and communication technology projects are subject to larger cost overruns than road construction projects). An important question is therefore whether there are combinations of field characteristics/features which can be measured objectively, such as field size, reservoir complexity, oil prices, and lack of drillstem tests (DSTs), etc., and which can be shown to have predictive power of overly optimistic and overconfident production forecasts. The data set in this study consists of 71 greenfield oil production forecasts at project sanction on the Norwegian Continental Shelf (NCS), with production starting between 1995 and 2020. Each forecast consists of a triplet of production curves which represent the statistical p10, the expectation, and the statistical p90. The forecasts are compared with actual production data. Metadata about the fields gathered from the Norwegian Petroleum Directorate (NPD) are used to establish 16 informative field features, from field reserves to the number of appraisal wells per unit area. These features are tested for predictive power, both individually and simultaneously, of optimism bias and of a general forecast quality metric. First, we show that value erosion caused by time overruns and production shortfalls are both significant, but that the relative importance of effects after production start is higher. Second, none of the tested machine learning models show any predictive power of forecasting bias. Because of this systematic presence of bias in the production forecasts, we argue that oil and gas companies need to make important changes to their decision-making workflows to take into account well-documented research findings on cognitive and organizational bias from the past decades, instead of the ever-increasing model complexity. Illustratively, as a final point, we show that a no-skills-involved reference class forecast based on empirical production curves from abandoned fields outperforms operators’ own greenfield forecasts. This approach may perhaps serve as a useful benchmark for future forecasts.

The cruise was part of the Centre of Excellence for Gas Hydrate, Environment and Climate (CAGE) at UiT – The Arctic University of Norway. It was partly supported by The Norwegian Petroleum Directorate (NPD). The cruise had the following scientific objectives: To do a seismic survey in areas with identified seepage sites in Storbanken to study the mechanisms controlling near-surface migration and seepage.To complement the cross-disciplinary data repository by CAGE in this area.To search for seafloor seepage sites based on regional structural features (e.g., fault lineaments, glaci-tectonic features) The cruise may be known as: CAGE18_1

E&P Notes (December 2022)

The research cruise was part of the Centre of Excellence (SFF) Centre for Arctic Gas Hydrate Environment and Climate (CAGE) at UiT – The Arctic University of Norway. It was partly supported by The Norwegian Petroleum Directorate. From Tromsø, we visited Sentralbankrenna and Hopendjupet in the central Barents Sea in order to pursue the following scientific objectives: – Identify gas seepage associated with known and assumed sandstone reservoirs sub-cropping at the sea floor. – Identify gas seepage related to leakage along faults and geological structures breaching the seafloor. – Collect gravity cores, multibeam and sub-bottom data to establish how grounding zone processes impact marine-based ice sheet behaviour and trigger ice-stream retreat during deglaciation. The cruise may be known as: CAGE20_2

The CAGE22-6 cruise on-board R/V Helmer Hanssen hosted UiT´s Arctic Marine Geology and Geophysics (GEO-8144 and GEO-3144) field course for PhD and Master students, and was carried out in collaboration with NPD – the Norwegian Petroleum Directorate and the INTPART project HOTMUD based at Centre for Earth Evolution and Dynamics (CEED) the University of Oslo. The cruise was also a part of the UNESCO Training Through Research program (formerly, The Floating University) and in the framework of this project is also coded as TTR22. The main scientific objectives of the cruise were to investigate: geological controls on fluid-flow dynamics on an uplifted, repeatedly glaciated, and eroded Northern Norwegian Barents Sea shelf and, the fate of the released hydrocarbons in the water column, on the sea surface, and in the atmosphere. The cruise may be known as: CAGE22_6

Drift simulation of a floating offshore wind turbine with broken mooring lines in a dynamic sea condition

It wasn’t too long ago that Arctic oil and gas exploration enjoyed celebrity status as the industry’s last frontier, chock full of gigantic unexplored hydrocarbon deposits just waiting to be developed. Fast forward and less than a decade later, the same climate change that made Arctic oil and gas more accessible has caused an about-face as governments and the world’s supranational energy companies rebrand and target control of greenhouse gases (GHG) to achieve carbon neutrality by 2050. Among countries with Arctic coastlines, Canada has focused its hydrocarbon production on its oil sands which sit well below the Arctic Circle; Greenland has decided to not issue any new offshore exploration licenses (https://jpt.spe.org/greenland-says-no-to-oil-but-yes-to-mining-metals-for-evs), and while Norway is offering licenses in its “High North,” the country can’t find many takers. The Norwegian Petroleum Directorate (NPD) reported that while 26 companies applied for licenses in 2013, this year’s bid round attracted only seven participants. Norway is Europe’s largest oil producer after Russia with half of its recoverable resources still undeveloped and most of that found in the Barents Sea where the NPD says only one oil field and one gas field are producing. That leaves Russia and the US—geopolitical rivals which are each blessed with large Arctic reserves and the infrastructure to develop those riches—but whose oil and gas industries play different roles in each nation’s economy and domestic political intrigues. Russia sees its Arctic reserves, particularly gas reserves, as vital to its national security, considering that oil and gas accounts for 60% of Russian exports and from 15 to 20% of the country’s gross domestic product (GDP), according to Russia’s Skolkovo Energy Centre. With navigation now possible year­round along the Northern Sea Route, Russia’s LNG champion and its largest independent gas producer, Novatek, is moving forward with exploration to expand its resource base and build infrastructure to ship product east to Asia and west to Europe. https://jpt.spe.org/russian­lng­aims­high­leveraging­big­reserves­and­logistical­advantages As a result, Russia’s state­owned majors—Rosneft, Gazprom, and Gazprom Neft—are lining up behind their IOC colleague as new investment in Arctic exploration and development is encouraged and rewarded by the Kremlin. In contrast, the American Petroleum Institute reports that the US oil and gas industry contributes 8% to US GDP, a statistic that enables the US to have a more diverse discussion than Russia about the role that oil and gas may play in any future energy mix. That is unless you happen to be from the state of Alaska where US Arctic oil and gas is synonymous with Alaskan oil and gas, and where the US Geological Survey estimates 27% of global unex­plored oil reserves may lie. Though Alaska is responsible for only 4% of US oil and gas production, those revenues covered two-thirds of Alaska’s state budget in 2020 despite the state’s decline in crude production in 28 of the past 32 years since it peaked at 2 million B/D in 1988, according to the US Energy Information Administration (EIA).

E&P Notes (May 2021)

E&P Notes (March 2021)

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30697, “From Completion to Production Without Intervention in a VXT Subsea Completed Well,” by Susanne Loen Ommundsen, Interwell, and Berit Sara Schiefloe and Olle Balstad, Equinor, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. As part of an improvement program focused on increasing standardization and efficiency on subsea well operations on the Norwegian continental shelf, the operator aimed to standardize future subsea wells using vertical trees (VXT) instead of horizontal trees. This would enable batch completion of several wells with a rig, followed by XT installation with an installation, maintenance, and repair (IMR) vessel, eliminating the need for a rig or lightweight intervention (LWI) vessel. The complete paper describes the development and implementation of a glass-plug solution that closed the technical gaps that had previously inhibited fully intervention-free operation for completion installation. Background and Field Information Trestakk is an oil and gas field in the Norwegian Sea in Block 6406/3. The field lies in 300 m of water approximately 27 km southeast of Åsgard A. Trestakk was discovered in 1986 and the plan for development and operation was approved in 2017. Equinor operates the field with 59.1% ownership interest, with Vår Energi owning the remaining 40.9%. The field development covers a subsea template with four well slots and one satellite well. A total of five wells will be drilled - three for production and two for gas injection. Production from the Trestakk subsea field on Haltenbanken in the Norwegian Sea began 16 July 2019. Trestakk is tied back to the Åsgard A floating production vessel. The Petroleum Safety Authority Norway and the Norwegian Petroleum Directorate approved the application for extending the lifetime of the installation to 2031 as a result of the additional recoverable volumes from Trestakk, for which field production is expected to last for 12 years. The goal for Trestakk was to achieve first recoverable oil at surface as soon as possible. The method selected was deployment of the completion string and VXT from a rig. The proposed solution was a barrier valve to be integrated as part of the completion string. As an operational improvement, the Trestakk team decided to design the wells with the intention of excluding wireline. Common methods for suspension and initiation of subsea wells during blowout-preventer (BOP) removal and VXT installation include installing shallow-set bridge plugs in the tubing or a tubing hanger plug. The plug is then removed using a riserless LWI vessel or rig. This method is often associated with high cost and enhanced operational risk.

Summary The oil and gas industry uses production forecasts to make decisions, which can be as mundane as whether to change the choke setting on a well, or as significant as whether to develop a field. These forecasts yield cash flow predictions and value-and-decision metrics such as net present value and internal rate of return. In this paper, probabilistic production forecasts made at the time of the development final investment decisions (FIDs) are compared with actual production after FIDs, to assess whether the forecasts are optimistic, overconfident, neither, or both. Although biases in time-and-cost estimates in the exploration and production (E&P) industry are well documented, probabilistic production forecasts have yet to be the focus of a comprehensive, public study. The main obstacle is that production forecasts for E&P development projects are not publicly available, even though they have long been collected by the Norwegian Petroleum Directorate (NPD), a Norwegian government agency. The NPD's guidelines specify that at the time of FID, the operators should report the forecasted annual mean and P10/90 percentiles for the projected life of the field. We arranged to access the NPD database in order to statistically compare annual production forecasts given at the time of FID for 56 fields in the 1995 to 2017 period, with actual annual production from the same fields. This work constitutes the first public study of the quality of probabilistic production forecasts. The main conclusions are that production forecasts that are being used at the FID for E&P development projects are both optimistic and overconfident, leading to poor decisions.1 1 The conclusions based on the analysis presented in this paper are limited to the set of fields from the NCS. However, other authors have demonstrated the optimism bias in production forecasts from fields around the world (Nandurdikar and Wallace 2011; Nandurdikar and Kirkham 2012).

Re-use of existing oil and gas infrastructure (pipelines, installations, wells) is often mentioned as an option to reduce the costs associated to Carbon Capture and Storage (CCS) deployment. The re-use of infrastructure entails, however, some challenges (e.g. infrastructure availability, capacity limitation, state). Total E&P Norge, together with Carbon Limits and NORCE, have looked more in detail at this topic in the 2nd Life CO2 project presented here. The aim of the 2nd Life CO2 project was to study, at a high level and not on a specific case-basis, the potential for re-use of offshore oil and gas pipelines, platforms and wells for CO2 transport throughout the North Sea in general, and the specific storage potential on the Norwegian Continental Shelf based on The Norwegian CO2 Storage Atlas developed by the Norwegian Petroleum Directorate. Alongside, an assessment of the economic and environmental benefits of such re-use was performed, and knowledge and data gaps were identified. In some cases, these gaps will require further de-risking to set up successful CCS projects involving re-use of infrastructure. For pipelines, open data sources from various countries (Norway, United Kingdom, Germany, Denmark and the Netherlands) were used in the project. Several tasks of the project had to be done in an automated way considering the high number of data points. This approach entails some limitations. Examples include specific aspects of the infrastructure, such as flow direction and to what extent pipelines are linked, which have an important impact on availability. The core idea of the approach was to estimate the year in which hydrocarbon fields are depleted (referred to its ‘end of life’) to determine the time at which the connected infrastructure is available. The end of life of each field was estimated based on resource depletion rather than economic cash-flow evaluations. The collected data set of remaining producible hydrocarbon volume was divided by data of current yearly production rate to estimates how long the fields could operate under current conditions. The assumption is that after this time the connected infrastructure (platform, wells and pipelines) becomes available. The corresponding infrastructure was classified and mapped, and only those available in the upcoming 20 years were studied further. Based on the availability mapping exercise, focus was put on the pipelines that link existing CO2 sources / potential hubs and CO2 storages. Both deep saline aquifers and depleted hydrocarbon fields were considered for CO2 storage. The storage potential for relevant storage sites in the vicinity of the reusable infrastructure was evaluated based on results from The Norwegian CO2 Storage Atlas and specific logs in the considered area. The results from this project displayed that overall, the Norwegian Continental Shelf (NCS) showed less infrastructure re-use potential in the coming 20 years compared to the UK continental shelf and offshore Netherlands. This finding was mainly related to the larger and less mature oil and gas fields on NCS. Thus, overall, the Netherlands and the UK seem more suited for smaller-scale re-use projects in a nearer future such as the Acorn project, whilst the Norwegian Continental Shelf seems more suited for larger-scale infrastructure re-use projects in more distant time-horizons. Some interesting cases on the Norwegian Continental Shelf were, however, singled out to be timely available of pipelines linking potential CO2 storage areas to shore. Given the limited number of large emitters in Norway in the vicinity of those pipelines, the best way to re-use those facilities would likely be to build an onshore hub that could import CO2 from large European emitters with an easy access to waterways or seaports. A few relevant cases were selected for economic and environmental assessment to compare the cost and environmental impact of re-use of oil and gas infrastructure for CCS with new built. The results of these assessments are presented in this article. Before launching CCS projects that make use of existing oil and gas infrastructure in the North Sea, there are, however, still significant data and technological uncertainties which need to be resolved. To ensure a satisfactory state of the re-used infrastructure as well as its availability, future re-use projects are recommended to align with decommissioning plans for oil and gas fields and related infrastructure.

PurposeThe purpose of this paper is to extend the understanding of projects in permanent organizations. Previous research has captured organizational contexts where either a project logic dominates or projects support recurrent, ongoing operations. Through a case study, the author shows how projects and non-projects coexist over time in the core of the organization in a balanced manner, addressing the specific tensions in such an organization.Design/methodology/approachThe author has undertaken a case study of the Norwegian Petroleum Directorate. The analysis is based on several types of data: internal reports, descriptions of structure and roles, internal handbooks and other documents from the period 1998–2018; interviews with ten persons in different roles in the organization; and a survey of 190 employees and middle managers (response rate: 84 percent).FindingsThe author finds that the balance of projects and non-project work, work units and rationale has been an institutional and stabile characteristic, rather than a transitory state of a Norwegian state directorate. It is also found that two types of products or set of tasks are reflected in two types of work groups: long-term work groups and project work groups. There is a subjective element regarding whether a new task should be integrated into an existing long-term unit or serve as the basis of creating a new project. The analysis of work organization, leadership and employee perceptions has revealed a number of similarities and differences between the two work contexts: the long-term work groups and the projects. The balance of projects and non-projects is maintained through shared beliefs and the process of allocation of personnel. This balance is threatened through actual practice in the organization.Research limitations/implicationsA case study does not allow for statistical generalizations. The implication of the study is the revelation of a potential research gap “between” a project-based organization (PBO), on the one hand, and a project-supported organization (PSO), on the other hand.Practical implicationsFor organizations that combine projects and non-projects in the core, the paper could contribute to the understanding of tensions and the way to handle them, and provide inspiration regarding mechanisms for resource allocation.Originality/valueThis paper identifies and empirically describes an organization where both projects and non-projects are of great importance in the core activities of the firm, thus filling a “gap” between the PBO and PSO. A number of aspects of this organization are analyzed, including how the balance of the two logics has been maintained over the two decades. The study could provide the basis for a number of research questions on the coexistence of and tensions between projects and non-projects in the core of an organization.

Can high-resolution reprocessed data replace the traditional 2D high-resolution seismic data acquired for site surveys?

The amount of provenance information available for onshore and offshore sedimentary deposits in the North Atlantic Region is substantial and rapidly increasing. These data provide an improved understanding of reservoir geology (quality, diagenetic issues, regional source-to-sink relations and local stratigraphic correlations), and thereby can reduce hydrocarbon exploration risk. As such, the number of proprietary, industry-related and public research provenance studies has increased considerably in recent years, and the development and use of new analytical techniques has also caused a surge in the number of grains, isotopes and chemical elements analysed in each study. As a result, it is today close to impossible for the individual researcher or petroleum geologist to draw on all existing provenance data. And the vast expansion of data availability demands new and better methods to analyse and visualise large amounts of data in a systematic way
 To this end, the Geological Survey of Denmark and Greenland (GEUS) and the Norwegian Petroleum Directorate (NPD) have established a web-based database of provenance data for the North Atlantic area: the North Atlantic Provenance Database. Construction of the database was funded jointly by GEUS and NPD. Future maintenance and further development will be funded by the petroleum industry by subscription to the database. Here, we provide a brief introduction to the database and its future development and expansion. We highlight the current capabilities with an example from East Greenland.

Depending on their specific geological properties, several types of geological formations can be used to store CO2. In the North Sea Basin, the greatest potential capacity for CO2 storage will be in deep saline-water saturated formations or in depleted oil and gas fields. The results presented in the CO2 Storage Atlas are based on studies of all relevant geological formations and hydrocarbon fields on the Norwegian Continental Shelf (NCS). Norwegian Petroleum Directorate (NPD) has access to all data collected from the petroleum industry and has a national management responsibility for these data. This is vested in the Norwegian Petroleum Law. More than 50 years of petroleum activity has generated a large quantity of data. These data and analyses together with many years of dedicated work to establish geological play models, have given us a good basis for the characterization and classification of potential CO2 storage sites. The first step in site selection is the screening of potentially suitable formations and structures using specific criteria. In the site selection process, it should be demonstrated that the potential sites have sufficient capacity to store the expected CO2 volume and sufficient injectivity for the expected rate of CO2 capture and supply. The integrity of the site must be assessed for the period required by the regulatory authority to avoid any unacceptable risks to the environment, human health or other uses of the subsurface. The aquifers were evaluated regarding reservoir quality and presence of relevant sealing formations. Those aquifers that may have a relevant storage potential in terms of depth, capacity and injectivity have been considered. The most attractive aquifers and structures were investigated by geomodelling and reservoir simulation. In all models, it is assumed that there will be no water production. The volumes of injected CO2 are constrained by the fracturing pressure. Our estimates of fracturing pressures are based on a large data base of leak-off tests and pore pressures in exploration wells. The regional fracture pressure trends are quite similar in North Sea and Norwegian Sea shelf, and somewhat lower in deeply eroded areas in the Barents Sea. The scores for capacity, injectivity and seal quality are based on evaluation of each aquifer/structure. The checklist for reservoir properties gives a more detailed overview of the important parameters regarding the quality of the reservoir. These parameters are set into different checklists for detailed grading.

The Norwegian Petroleum Directorate (NPD) presented a CO2 Storage Atlas for the Norwegian Continental Shelf (NCS) in 2014. The main objective with this Atlas was to identify safe and effective areas for long-term storage of CO2. There are more than 22 years of experience with storage of CO2 in geological formations offshore Norway and a lot of work has been done to map, characterize and evaluate potential storage sites. To get an overview of the possibility of using captured CO2 for enhanced recovery (EOR), several screening studies were conducted. The technology for CO2 used for EOR is well documented for onshore fields. Implementing CO2 for EOR offshore will be more challenging and can carry operational, commercial and financial risks. In this paper, we present the results from three different screening studies on storage of CO2 combined with EOR in oil fields in the Norwegian part of the North Sea and one residual oil study (ROZ) from an oil discovery in the Barents Sea. The input to these studies are production history and characteristics from the different oil fields and the results are based on reservoir simulation from screening studies on these fields. The results from these studies are purely technical, no detailed economic evaluation has been done. The aim was to study the possibility and potential of using CO2 for EOR on some of the mature offshore oil fields in combination with storing CO2 in the underground. All these studies showed very interesting results.

Editor's column Late December/early January is the time of year when industry outlooks are announced, revealing company spending plans, oil price predictions, and potential stumbling blocks. The steep drop in prices in the fourth quarter of 2018 made these outlooks particularly challenging, and most are laced with cautious optimism about the year ahead. But common themes emerge: the industry is still in cost-containment recovery mode; the march toward digitalization is in full swing; and shale output from the US will only increase as pipeline bottlenecks began to ease with new construction. This past year was one of recovery, as the downturn that began with the price crash in 2014 appeared to be over, although that view is not unanimous. Capital expenditures rose last year because of higher oil prices but spending was cautious, and that caution was validated when both Brent and WTI prices fell about $30/bbl during the fourth quarter. A price rally in January began to ease concerns that the industry was in another free fall. Oil and gas spending growth rose 4% in 2017 and 5% in 2018, according to the International Energy Agency (IEA), after dropping 60% during 2014–16. The US shale sector contributed largely to that growth, as spending on unconventionals outstripped interest in conventional oil and offshore. Majors increased their visibility in unconventionals in plays such as the Permian Basin. Shale remains a bright spot, and will allow the US to likely remain the world’s largest producer of liquids and gas. Global oil inventories have come down significantly since the downturn, even with the increase in US production. But major uncertainties exist, making this year “even more hazardous than usual” to forecast trends in 2019, an IEA spokesman was quoted as saying. That uncertainty is reflected in a recent survey of more than 30 oil analysts, who predicted that Brent prices would end the year anywhere from $30/bbl to $78/bbl. Deloitte’s 2019 industry outlook states that “opportunities from digital technologies are becoming increasingly apparent and have the potential to unlock new value.” As featured in JPT over the past year in particular, more companies are employing or experimenting with artificial intelligence, automation, machine learning, robotics, and blockchain, often attracting nontraditional vendors and startups. The offshore sector has yet to recover. US Gulf of Mexico (GOM) production rose last year but drilling activity did not, and the rig count ended the year at an 81% utilization rate. There were 36 active deepwater GOM sites at the end of the year, compared with 49 in early 2017, according to the US Bureau of Safety and Environmental Enforcement. Norway’s upstream regulator is not optimistic about spending there. Oil and gas production will fall 4.7% this year to 1.42 million B/D after a 6% drop last year, according to an annual report by the Norwegian Petroleum Directorate. Mexico’s offshore may be a bright spot, but the industry is still looking for signals from the new government that it is friendly toward private sector E&P.